Systems and methods for optimizing stoichiometric combustion

ABSTRACT

Provided are more efficient techniques for operating gas turbine systems. In one embodiment a gas turbine system comprises an oxidant system, a fuel system, a control system, and a number of combustors adapted to receive and combust an oxidant from the oxidant system and a fuel from the fuel system to produce an exhaust gas. The gas turbine system also includes a number of oxidant-flow adjustment devices, each of which are operatively associated with one of the combustors, wherein an oxidant-flow adjustment device is configured to independently regulate an oxidant flow rate into the associated combustor. An exhaust sensor is in communication with the control system. The exhaust sensor is adapted to measure at least one parameter of the exhaust gas, and the control system is configured to independently adjust each of the oxidant-flow adjustment devices based, at least in part, on the parameter measured by the exhaust sensor.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of U.S. application Ser. No.13/805,646 entitled SYSTEMS AND METHODS FOR OPTIMIZING STOICHIOMETRICCOMBUSTION filed on 19 Dec. 2012, which is the National Stage entryunder 35 U.S.C. 371 of PCT/US2011/042000, that published asWO2012/018457 and was filed on 27 Jun. 2011 which claims the benefit ofU.S. Provisional Application 61/371,523 filed on 6 Aug. 2010, each ofwhich is incorporated by reference, in its entirety, for all purposes.

FIELD

The present disclosure relates generally to low-emission powergeneration systems. More particularly, the present disclosure relates tosystems and methods for optimizing substantially stoichiometriccombustion in gas turbine systems.

BACKGROUND

This section is intended to introduce various aspects of the art, whichmay be associated with exemplary embodiments of the present techniques.This discussion is believed to assist in providing a framework tofacilitate a better understanding of particular aspects of the presenttechniques. Accordingly, it should be understood that this sectionshould be read in this light, and not necessarily as admissions of priorart.

The combustion of fuel within a combustor, e.g., integrated with a gasturbine, can be controlled by monitoring the temperature of the exhaustgas. At full load, typical gas turbines adjust the amount of fuelintroduced to a number of combustors in order to reach a desiredcombustion gas or exhaust gas temperature. Conventional combustionturbines control the oxidant introduced to the combustors using inletguide vanes. At partial load, the amount of oxidant introduced to thecombustor is reduced and the amount of fuel introduced is againcontrolled to reach the desired exhaust gas temperature. At partialload, the efficiency of gas turbines drops because the ability to reducethe amount of oxidant is limited by the inlet guide vanes, which areonly capable of slightly reducing the flow of oxidant. Further, theoxidant remains at a constant lower flow rate when the inlet guide vanesare in their flow restricting position. The efficiency of the gasturbine then drops when it is at lower power production because to makethat amount of power with that mass flow a lower expander inlettemperature is required. Moreover, existing oxidant inlet controldevices may not allow fine flow rate control and may introduce largepressure drops with any restriction on the oxidant flow. With either ofthese approaches to oxidant control, there are potential problems withlean blow out at partial load or reduced pressure operations.

Controlling the amount of oxidant introduced to the combustor can bedesirable when an objective is to capture carbon dioxide (CO₂) from theexhaust gas. Current carbon dioxide capture technology is expensive dueto several reasons. One reason is the low pressure and low concentrationof carbon dioxide in the exhaust gas. The carbon dioxide concentration,however, can be significantly increased from about 4% to greater than10% by operating the combustion process under substantiallystoichiometric conditions. Further, a portion of the exhaust gas may berecycled to the combustor as a diluent in order to control thetemperature of the exhaust gas. Also, any unused oxygen in the exhaustgas may be a contaminate in the captured carbon dioxide, restricting thetype of solvents that can be utilized for the capture of carbon dioxide.

In many systems, an oxidant flow rate may be reduced by altering theoperation of a separate oxidant system. For example, an independentoxidant compressor may be throttled back to a slower operating speedthereby providing a decreased oxidant flow rate. However, the reductionin compressor operating speed generally decreases the efficiency of thecompressor. Additionally, throttling the compressor may reduce thepressure of the oxidant entering the combustor. In contrast, if theoxidant is provided by the compressor section of the gas turbine,reducing the speed is not a variable that is controllable during powergeneration. Gas turbines that are used to produce 60 cycle power aregenerally run at 3,600 rpm. Similarly, to produce 50 cycle power the gasturbine is often run at 3,000 rpm. In conventional gas turbine combustoroperations the flow of oxidant into the combustor may not warrantsignificant control because the excess oxidant is used as coolant in thecombustion chamber to control the combustion conditions and thetemperature of the exhaust gas. A number of studies have been performedto determine techniques for controlling combustion processes in gasturbines.

For example, U.S. Pat. No. 6,332,313 to Willis, et al., discloses acombustion chamber with separate, valved air mixing passages forseparate combustion zones. A combustion chamber assembly includes aprimary, a secondary and a tertiary fuel and air mixing ducts to supplyfuel and air to each of primary, secondary and tertiary combustionzones, respectively. Each of the primary, secondary and tertiary fueland air mixing ducts includes a pair of axial flow swirlers, which arearranged coaxially to swirl the air in opposite directions and fuelinjectors to supply fuel coaxially to the respective axial flowswirlers. Valves are provided to control the supply of air to theprimary and the secondary fuel and air mixing ducts respectively. A ductis arranged to supply cooling air and dilution air to the combustionchamber. The amount of air supplied to the primary, secondary andtertiary fuel and air mixing ducts and the duct is measured.

International Patent Application Publication No. WO/2010/044958 byMittricker, et al., discloses methods and systems for controlling theproducts of combustion, for example, in a gas turbine system. Oneembodiment includes a combustion control system having an oxygenationstream substantially comprising oxygen and CO₂ and having an oxygen toCO₂ ratio, then mixing the oxygenation stream with a combustion fuelstream and combusting in a combustor to generate a combustion productsstream having a temperature and a composition detected by a temperaturesensor and an oxygen analyzer, respectively. The data from the sensorsare used to control the flow and composition of the oxygenation andcombustion fuel streams. The system may also include a gas turbine withan expander and having a load and a load controller in a feedbackarrangement.

International Patent Application Publication No. WO/2009/120779 byMittricker, et al., discloses systems and methods for low emission powergeneration and hydrocarbon recovery. One system includes integratedpressure maintenance and miscible flood systems with low emission powergeneration. Another system provides for low emission power generation,carbon sequestration, enhanced oil recovery (EOR), or carbon dioxidesales using a hot gas expander and external combustor. Another systemprovides for low emission power generation using a gas power turbine tocompress air in the inlet compressor and generate power using hot carbondioxide laden gas in the expander.

U.S. Pat. No. 4,858,428 to Paul discloses an advanced integratedpropulsion system with total optimized cycle for gas turbine. Pauldiscloses a gas turbine system with integrated high and low pressurecircuits having a power transmission for extracting work from one of thecircuits, the volume of air and fuel to the respective circuits beingvaried according to the power demand monitored by a microprocessor. Theturbine system has a low pressure compressor and a staged high pressurecompressor with a combustion chamber and high pressure turbineassociated with the high pressure compressor. A combustion chamber and alow pressure turbine are associated with the low pressure compressor,the low pressure turbine being staged with the high pressure turbine toadditionally receive gases expended from the high pressure turbine and amicroprocessor to regulate air and gas flows between the compressor andturbine components in the turbine system.

U.S. Pat. No. 4,271,664 to Earnest discloses a turbine engine withexhaust gas recirculation. The engine has a main power turbine operatingon an open-loop Brayton cycle. The air supply to the main power turbineis furnished by a compressor independently driven by the turbine of aclosed-loop Rankine cycle which derives heat energy from the exhaust ofthe Brayton turbine. A portion of the exhaust gas is recirculated intothe compressor inlet during part-load operation.

U.S. Patent Application Publication No. 2009/0064653 by Hagen, et al.,discloses partial load combustion cycles. The part load method controlsdelivery of diluent fluid, fuel fluid, and oxidant fluid inthermodynamic cycles using diluent to increase the turbine inlettemperature and thermal efficiency in part load operation above thatobtained by relevant art part load operation of Brayton cycles, foggedBrayton cycles, or cycles operating with some steam delivery, or withmaximum steam delivery.

While some past efforts to control the oxidant flow rate haveimplemented oxidant inlet control devices, such systems disclosed acontrol of all of the combustors together, failing to account fordifferences between combustors. Further, the systems were limited intheir ability to finely tune the oxidant flow rate.

SUMMARY

An exemplary embodiment of the present techniques provides a gas turbinesystem. The gas turbine system includes an oxidant system, a fuelsystem, a control system, and a plurality of combustors adapted toreceive and combust an oxidant from the oxidant system and a fuel fromthe fuel system to produce an exhaust gas. An oxidant-flow adjustmentdevice is operatively associated with each one of the combustors. Theoxidant-flow adjustment device is configured to independently regulatean oxidant flow rate into the associated combustor. An exhaust sensor isin communication with the control system. The exhaust sensor is adaptedto measure at least one parameter of the exhaust gas, and the controlsystem is configured to independently adjust each of the plurality ofoxidant-flow adjustment devices based, at least in part, on theparameter measured by the exhaust sensor.

The oxidant may include oxygen and a diluent. A diluent supply isprovided to each of the plurality of combustors. An oxidant compressormay be used to provide compressed oxidant to the combustors.

The oxidant-flow adjustment device may include a flow control valve. Theoxidant-flow adjustment device may include an adjustable swirler subassembly. The adjustable swirler sub assembly may include an annularcontrol assembly positioned around a flow sleeve to controllablyregulate oxidant flow rates into the flow sleeve. The annular controlassembly includes a plurality of articulating vanes operativelyassociated with a mounting ring and an actuator vane. The plurality ofvanes is adapted to be controllably adjusted between an open positionand a closed position and positions therebetween by moving the actuatorvane relative to the mounting vane.

The gas turbine may include a plurality of exhaust sensors that areadapted to work with the control system to regulate oxidant flow ratesto each of the plurality of combustors so as to minimize differencesbetween measured parameters at different exhaust sensors. Theoxidant-flow adjustment device on at least one of the plurality ofcombustors is adapted to increase mixing of the oxidant, the fuel, adiluent, or any combinations thereof.

A combustor may include a diluent inlet and an oxidant inlet, in whichan oxidant-flow adjustment device is disposed in the oxidant inlet. Theoxidant-flow adjustment device may be configured to mix the oxidant andthe diluent before the fuel is introduced.

A turbine expander may be adapted to receive the exhaust gas and togenerate power. A heat recovery steam generator may be adapted toreceive the exhaust gas from the turbine expander and to generate power.A diluent compressor and an exhaust gas recirculation loop may beadapted to receive the exhaust gas from the expander, in which theexhaust gas recirculation loop includes a heat recovery steam generatoradapted to generate power, and a cooled exhaust line can be adapted toprovide cooled exhaust gas to the diluent compressor, and in which thediluent compressor is adapted to provide compressed diluent to thecombustor.

An exhaust gas extraction system may be disposed between the diluentcompressor and the combustor, wherein the exhaust gas extraction systemmay extract diluent at elevated pressures.

Another exemplary embodiment provides a method of controlling a gasturbine. The method includes providing a fuel to a plurality ofcombustors on a gas turbine, and providing an oxidant to the pluralityof combustors, wherein an oxidant flow rate is independently adjustedfor each of the plurality of combustors. The fuel and the oxidant arecombusted in the plurality of combustors to produce an exhaust gas. Aparameter of the exhaust gas is measured and the oxidant flow rate intoeach of the plurality of combustors is adjusted to control the parameterto within a target set-point range.

The method may include compressing the oxidant before the oxidant isprovided to each of the plurality of combustors. A portion of theexhaust gas may be returned to the plurality of combustors as a diluent.The diluent may be compressed with a compressor before the diluententers the combustor. The compressor may be operatively coupled to anexpander adapted to receive the exhaust gas and to generate powertherefrom.

At least a portion of the exhaust gas may be extracted from a couplingdisposed between the compressor and each of the plurality of combustors,wherein the amount of exhaust gas extracted is based, at least in part,on the parameter.

Another exemplary embodiment provides a non-transitory computer readablemedium comprising code configured to direct a processor to provide afuel to a plurality of combustors on a gas turbine and provide anoxidant to the plurality of combustors, wherein an oxidant flow rate isindependently adjusted for each of the plurality of combustors. The codealso directs the processor to monitor a parameter of an exhaust gasproduced in a flame in the combustors and adjust the oxidant flow rateinto each of the plurality of combustors to control the parameter towithin a target set-point range. The parameter may be a concentration ofoxygen in the exhaust gas. The parameter may be a concentration ofcarbon monoxide in the exhaust gas.

The non-transitory computer readable medium may include a data structurerepresenting a swirl chart. The code may be configured to direct theprocessor to compare measurements associated with a plurality of sensorsto the data structure to determine which of the plurality of combustorsto adjust. The code may be configured to direct the processor to obtainmeasurements from a plurality of exhaust sensors. The code may beconfigured to direct the processor to regulate oxidant flow rates toeach of the plurality of combustors so as to minimize differencesbetween measured parameters at different exhaust sensors.

DESCRIPTION OF THE DRAWINGS

The advantages of the present techniques are better understood byreferring to the following detailed description and the attacheddrawings, in which:

FIG. 1 is a schematic diagram of a gas turbine system that includes agas turbine;

FIG. 2 is a diagram illustrating a portion of a combustor, such as thecombustors discussed with respect to FIG. 1;

FIG. 3 is a drawing of a swirler, as discussed with respect to FIG. 2;

FIG. 4 is a schematic of a gas turbine system that can be used toindividually adjust the oxidant flow to each of a number of combustors;

FIG. 5 is a schematic of a gas turbine system that includes sensors onthe turbine expander;

FIG. 6 is a schematic of a gas turbine system that includes sensors onthe exhaust line out of each combustor;

FIG. 7 is a schematic of a gas turbine system that includes a separateoxidant flow adjusting valve on the oxidant supply line for eachcombustor;

FIG. 8 is a schematic of a gas turbine system that includes a heatrecovery steam generator (HRSG) on the exhaust stream from the expanderexhaust section;

FIG. 9 is a schematic of a gas turbine system that includes a sensor onthe exhaust stream from the expander exhaust section to a heat recoverysteam generator (HRSG);

FIG. 10 is a schematic of a gas turbine system that includes a sensor onthe cooled exhaust stream from the HRS G;

FIG. 11 is a schematic of a gas turbine system that includes a cooler onthe cooled exhaust stream from the HRS G;

FIG. 12 is a schematic of a gas turbine system that combines featuresfrom a number of the systems discussed above;

FIGS. 13A and 13B are graphical depictions of a simulation showing therelationship between the concentration of oxygen and carbon monoxide asthe equivalence ratio (ϕ) changes from 0.75 to 1.25 and from 0.999 to1.001, respectively;

FIG. 14 is a block diagram of a method for biasing individual combustorsbased on readings from an array of sensors; and

FIG. 15 is a block diagram of a plant control system that may be used toindividually control the oxidant and fuel to a number of combustors in agas turbine.

DETAILED DESCRIPTION

In the following detailed description section, specific embodiments ofthe present techniques are described. However, to the extent that thefollowing description is specific to a particular embodiment or aparticular use of the present techniques, this is intended to be forexemplary purposes only and simply provides a description of theexemplary embodiments. Accordingly, the techniques are not limited tothe specific embodiments described below, but rather, include allalternatives, modifications, and equivalents falling within the truespirit and scope of the appended claims.

At the outset, for ease of reference, certain terms used in thisapplication and their meanings as used in this context are set forth. Tothe extent a term used herein is not defined below, it should be giventhe broadest definition persons in the pertinent art have given thatterm as reflected in at least one printed publication or issued patent.Further, the present techniques are not limited by the usage of theterms shown below, as all equivalents, synonyms, new developments, andterms or techniques that serve the same or a similar purpose areconsidered to be within the scope of the present claims.

An “adsorbent” may be used to extract or sequester CO₂ from an exhaustgas flow. The absorbent may be used in a series of parallel beds, whichcan be switched when an absorbent in a bed has reached capacity. The bedthat is removed from the flow can then be treated, such as heated, todesorb the CO₂.

Suitable adsorbents for CO₂ sequestration in the present applicationshave reasonably large working capacity over the relevant temperaturerange and composition range, good selectivity for CO₂ over otherundesired constituents (such as N₂ and O₂), good kinetics, highdurability, good compatibility, and reasonably low cost. Several solidphase adsorbents are potential candidates for CO₂ capture. For example,molecular sieves are materials whose atoms are arranged in a lattice orframework in such a way that a large number of interconnected uniformlysized pores exist. The pores generally only admit molecules of a sizeabout equal to or smaller than that of the pores. Molecular sieves,thus, can be used to adsorb and separate or screen molecules based ontheir size with respect to the pores. One class of molecular sieves iszeolites. Zeolites are hydrated silicates of aluminum and frequentlycontain cations, which are exchangeable. Zeolites can be naturallyoccurring or artificial. Naturally occurring types include chabazite,clinoptilolite, erionite, heulandite, and mordenite, to name but a few.Artificial zeolites including, for example, types A, D, L, R, S, T, X,Y, ZSM, mordenite, or clinoptilolite, may also be used. Liquid phase, orsolvent adsorption systems, such as those based on chemisorption, mayalso be used. These may include systems based on carbonates, or amines,among others.

“Physical absorption” means absorbing a product, such as carbon dioxide,from a gaseous feed stream by passing the feed stream into a liquidwhich preferentially adsorbs the product from the feed stream at arelatively high pressure, for example, about 2.07 to 13.8 MPa. The feedstream that is depleted of the absorbed product is removed from theliquid. The product can then be recovered from the liquid such as bylowering the pressure over the liquid or by stripping the product out ofthe liquid. Unlike other solvent based processes, such as those based onamines or carbonates, the absorption of the carbon dioxide into theliquid does not involve a chemical reaction of the carbon dioxide. Anexample of a physical adsorption process is the SELEXOL™ processavailable from the UOP LLC subsidiary of the HONEYWELL Corporation.

A “carbon sequestration facility” is a facility in which carbon dioxidecan be controlled and sequestered in a repository such as, for example,by introduction into a mature or depleted oil and gas reservoir, anunmineable coal seam, a deep saline formation, a basalt formation, ashale formation, or an excavated tunnel or cavern. Further,sequestration can be combined with other uses for the sequestered gas,such as increasing hydrocarbon production in tertiary oil recovery froman active reservoir.

A “combined cycle power plant” uses both steam and gas turbines togenerate power. The gas turbine operates in an open Brayton cycle, andthe steam turbine operates in a Rankine cycle powered by the heat fromthe gas turbine. These combined cycle gas/steam power plants generallyhave a higher energy conversion efficiency than gas or steam onlyplants. A combined cycle plant's efficiencies can be as high as 50% to60%. The higher combined cycle efficiencies result from synergisticutilization of a combination of the gas turbine with the steam turbine.Typically, combined cycle power plants utilize heat from the gas turbineexhaust to boil water to generate steam. The boilers in typical combinedcycle plants can be referred to as heat recovery steam generator (HRSG).The steam generated is utilized to power a steam turbine in the combinedcycle plant. The gas turbine and the steam turbine can be utilized toseparately power independent generators, or in the alternative, thesteam turbine can be combined with the gas turbine to jointly drive asingle generator via a common drive shaft.

A diluent is a gas used to lower the concentration of oxidant fed to agas turbine to combust a fuel. The diluent may be an excess of nitrogen,CO₂, combustion exhaust, or any number of other gases. In embodiments, adiluent may also provide cooling to a combustor.

As used herein, a “compressor” includes any type of equipment designedto increase the pressure of a working fluid, and includes any one typeor combination of similar or different types of compression equipment. Acompressor may also include auxiliary equipment associated with thecompressor, such as motors, and drive systems, among others. Thecompressor may utilize one or more compression stages, for example, inseries. Illustrative compressors may include, but are not limited to,positive displacement types, such as reciprocating and rotarycompressors for example, and dynamic types, such as centrifugal andaxial flow compressors, for example. For example, a compressor may be afirst stage in a gas turbine engine, as discussed in further detailbelow.

A “control system” typically comprises one or more physical systemcomponents employing logic circuits that cooperate to achieve a set ofcommon process results. In an operation of a gas turbine engine, theobjectives can be to achieve a particular exhaust composition andtemperature. The control system can be designed to reliably control thephysical system components in the presence of external disturbances,variations among physical components due to manufacturing tolerances,and changes in inputted set-point values for controlled output values.Control systems usually have at least one measuring device, whichprovides a reading of a process variable, which can be fed to acontroller, which then can provide a control signal to an actuator,which then drives a final control element acting on, for example, anoxidant stream. The control system can be designed to remain stable andavoid oscillations within a range of specific operating conditions. Awell-designed control system can significantly reduce the need for humanintervention, even during upset conditions in an operating process.

An “equivalence ratio” refers to the mass ratio of fuel to oxygenentering a combustor divided by the mass ratio of fuel to oxygen whenthe ratio is stoichiometric. A perfect combustion of fuel and oxygen toform CO₂ and water would have an equivalence ratio of 1. A too leanmixture, e.g., having more oxygen than fuel, would provide anequivalence ratio less than 1, while a too rich mixture, e.g., havingmore fuel than oxygen, would provide an equivalence ratio greater than1.

A “fuel” includes any number of hydrocarbons that may be combusted withan oxidant to power a gas turbine. Such hydrocarbons may include naturalgas, treated natural gas, kerosene, gasoline, or any number of othernatural or synthetic hydrocarbons.

A “gas turbine” engine operates on the Brayton cycle. If the exhaust gasis vented, this is termed an open Brayton cycle, while recycling of theexhaust gas gives a closed Brayton cycle. As used herein, a gas turbinetypically includes a compressor section, a number of combustors, and aturbine expander section. The compressor may be used to compress anoxidant, which is mixed with a fuel and channeled to the combustors. Themixture of fuel and oxidant is then ignited to generate hot combustiongases. The combustion gases are channeled to the turbine expandersection which extracts energy from the combustion gases for powering thecompressor, as well as producing useful work to power a load. Inembodiments discussed herein, the oxidant may be provided to thecombustors by an external compressor, which may or may not bemechanically linked to the shaft of the gas turbine engine. Further, inembodiments, the compressor section may be used to compress a diluent,such as recycled exhaust gases, which may be fed to the combustors as acoolant.

A “heat recovery steam generator” or HRSG is a heat exchanger or boilerthat recovers heat from a hot gas stream. It produces steam that can beused in a process or used to drive a steam turbine. A common applicationfor an HRSG is in a combined-cycle power plant, where hot exhaust from agas turbine is fed to the HRSG to generate steam which in turn drives asteam turbine. This combination produces electricity more efficientlythan either the gas turbine or steam turbine alone.

A “hydrocarbon” is an organic compound that primarily includes theelements hydrogen and carbon, although nitrogen, sulfur, oxygen, metals,or any number of other elements may be present in small amounts. As usedherein, hydrocarbons generally refer to components found in raw naturalgas, such as CH₄, C₂H₂, C₂H₄, C₂H₆, C₃ isomers, C₄ isomers, benzene, andthe like.

An “oxidant” is a gas mixture that can be flowed into the combustors ofa gas turbine engine to combust a fuel. As used herein, the oxidant maybe oxygen mixed with any number of other gases as diluents, includingCO₂, N₂, air, combustion exhaust, and the like.

A “sensor” refers to any device that can detect, determine, monitor,record, or otherwise sense the absolute value of or a change in aphysical quantity. A sensor as described herein can be used to measurephysical quantities including, temperature, pressure, O₂ concentration,CO concentration, CO₂ concentration, flow rate, acoustic data, vibrationdata, chemical concentration, valve positions, or any other physicaldata.

“Pressure” is the force exerted per unit area by the gas on the walls ofthe volume. Pressure can be shown as pounds per square inch (psi).“Atmospheric pressure” refers to the local pressure of the air.“Absolute pressure” (psia) refers to the sum of the atmospheric pressure(14.7 psia at standard conditions) plus the gage pressure (psig). “Gaugepressure” (psig) refers to the pressure measured by a gauge, whichindicates only the pressure exceeding the local atmospheric pressure(i.e., a gauge pressure of 0 psig corresponds to an absolute pressure of14.7 psia). The term “vapor pressure” has the usual thermodynamicmeaning. For a pure component in an enclosed system at a given pressure,the component vapor pressure is essentially equal to the total pressurein the system.

“Substantial” when used in reference to a quantity or amount of amaterial, or a specific characteristic thereof, refers to an amount thatis sufficient to provide an effect that the material or characteristicwas intended to provide. The exact degree of deviation allowable may insome cases depend on the specific context.

Overview

Embodiments of the present invention provide a system and a method forindividually controlling a number of combustors on a gas turbine engine.The control may be based, at least in part, on measurements fromsensors, for example, located in a ring on an exhaust expander. Thesensors may include oxygen sensors, carbon monoxide sensors, andtemperature sensors, among others. Further, combinations of differenttypes of sensors may be used to provide further information.

The sensors may not have a one-to-one relationship to particularcombustors, but may be influenced by a particular combustor. Theresponse of various sensors may be related back to a particularcombustor, for example, using sum and difference algorithms that may bebased on swirl charts. Swirl charts relate patterns of exhaust flow inan expander to combustors that may have contributed to the exhaust flowat that point.

The use of individually controlled combustors may increase the burnefficiency of a gas turbine engine, e.g., making the burn closer to aone-to-one equivalence ratio. Such improvements in efficiency may lowerO₂ and unburned hydrocarbons in the exhaust and make capturing CO₂ fromthe exhaust gas more efficient. This may improve the capture of the CO₂from the turbine for use in enhanced oil recovery, as well as insequestration.

FIG. 1 is a schematic diagram of a gas turbine system 100 that includesa gas turbine 102. The gas turbine 102 may have a compressor 104 and aturbine expander 106 on a single shaft 108. The gas turbine 102 is notlimited to a single shaft arrangement, as multiple shafts could be used,generally with mechanical linkages or transmissions between shafts. Inembodiments, the gas turbine 102 also has a number of combustors 110that feed hot exhaust gas to the expander, for example, through lines112. For example, a gas turbine 102 may have 2, 4, 6, 14, 18, or evenmore combustors 110, depending on the size of the gas turbine 102.

The combustors 110 are used to burn a fuel provided by a fuel source114. An oxidant may be provided to each of the combustors 110 fromvarious sources. For example, in embodiments, an external oxidant source116, such as an external compressor, may provide the oxidant to thecombustors 110. In embodiments, an oxidant or recycled exhaust gases118, or a mixture thereof, may be compressed in the compressor 104 andthen provided to the combustors 110. In other embodiments, such as whenan external oxidant source 116 is provided, the compressor 104 may beused to compress only the recycled exhaust gas, which may be fed to thecombustors 110 for cooling and dilution of the oxidant.

The exhaust gas from the combustors 110 expands in the turbine expander106, creating mechanical energy. The mechanical energy may power thecompressor 104 through the shaft 108. Further, a portion of themechanical energy may be harvested from the gas turbine as a mechanicalpower output 120, for example, to generate electricity or to poweroxidant compressors. The expanded exhaust gas 122 may be vented, usedfor heat recovery, recycled to the compressor 104, or used in anycombinations thereof.

In embodiments, the oxidant can be individually metered to each of thecombustors 110 to control an equivalence ratio in that combustor 110. Itwill be apparent to one of skill in the art that a stoichiometric burn,e.g., at an equivalence ratio of 1, will be hotter than anon-stoichiometric burn. Therefore, either excess oxidant or an addednon-combustible gas, such as a recycle exhaust gas, can be added to coolthe engine, preventing damage to the combustors 110 or the turbineexpander 106 from the extreme heat. The use of recycled exhaust gas 122provides a further advantage in that the exhaust is deficient in oxygen,making it a better material for enhanced oil recovery. Further,individually adjusting the oxidant to each combustor 110, for example,as discussed with respect to FIGS. 2 and 3, may compensate fordifferences between the combustors 110, improving the overall efficiencyof the gas turbine 102. Control of the mixture parameters to each of thecombustors 110 is discussed further with respect to FIGS. 13A, 13B, and14.

FIG. 2 is a diagram 200 illustrating a portion of a combustor, such asthe combustors 110 discussed with respect to FIG. 1. It will be clearthat this is merely one example of a combustor 110, as many otheroptions are available. As shown in the diagram 200, an oxidant 202 maybe fed into an adjustable oxidant swirler 204. The swirler 204 may bemore widely opened or partially closed by moving an actuator ring 206,as discussed further with respect to FIG. 3. The swirler 204 creates aspiraling gas flow 208 of that may enhance mixing, for example, of airwith recycled exhaust gas in an oxidant flow, or an oxidant with fuel.Fuel 210 may be injected through a separate flow path 212, for example,along the outside of the spiraling gas 208, which may heat the fuel 210,enhancing the burn. Injection of the fuel 210 is not limited to aseparate flow path 212, as the fuel 210 may be injected in any number ofplaces. For example, a preheated stream of fuel 214 may be injected downthe center of the swirler 204, mixing with the oxidant 202 in the spiralflow path 208. The fuel 210 is mixed with the oxidant 202 prior toentering a combustion zone 216, in which the fuel 210 and oxidant 202are consumed in a flame 218. The adiabatic flame temperature of astoichiometric combustion of methane in air is about 1960° C. and astoichiometric combustion of methane in oxygen is about 2800° C.).Accordingly, cooling may be needed to decrease the chance of damage tothe equipment. Thus, in embodiments, a diluent may be added to oxidant202 for cooling purposes as it is injected into the adjustable oxidantswirler 204. In embodiments, the diluent may be recycled exhaust gas,nitrogen, or other gases that do not participate in the combustionprocess.

FIG. 3 is a drawing of a swirler 204, as discussed with respect to FIG.2. The swirler 204 has a number of vanes 302 that direct an oxidant flow304 through a throat opening 306 between each of the vanes 302. Anactuator ring 206 can be used to adjust the size of the throat openings306. For example, when the actuator ring changes angle, the vanes 302can open or close, adjusting the oxidant flow 304 into the throat 308.An adjustable swirler 204 may be included in each combustor 110 (FIG. 1)to modify the oxidant amount fed to the combustor 110. A system that mayuse a swirler 204 to adjust the amount of oxidant to each combustor 110is shown in FIG. 4.

Individual Control of Oxidant to Combustors

FIG. 4 is a schematic of a gas turbine system 400 that can be used toindividually adjust the oxidant flow to each of a number of combustors110. The referenced units are as generally discussed with respect toFIG. 1. The system 400 uses an oxidant flow adjusting device 402, suchas the swirler 204 discussed above, and a mixing section in eachcombustor 110. An actuator 404 can be used to adjust the oxidant flowadjusting device 402.

A number of sensors 406 can be placed in an expander exhaust section 408of the gas turbine 102, for example, 5, 10, 15, 20, 25, 30 or more,sensors 406 may be placed in a ring around the expander exhaust section408. The number of sensors 406 may be determined by the size of the gasturbine 102. The sensors 406 may be any of the types discussed herein,including oxygen sensors, carbon monoxide sensors, temperature sensors,and the like. Examples of oxygen sensors can include lambda and/orwideband zirconia oxygen sensors, titania sensors, galvanic, infrared,or any combination thereof. Examples of temperature sensors can includethermocouples, resistive temperature devices, infrared sensors, or anycombination thereof. Examples of carbon monoxide sensors can includeoxide based film sensors such as barium stannate and/or titaniumdioxide. For example, a carbon monoxide sensor can includeplatinum-activated titanium dioxide, lanthanum stabilized titaniumdioxide, and the like. The choice of the sensors 406 may be controlledby the response time, as the measurements are needed for real timecontrol of the system. The sensors 406 may also include combinations ofdifferent types of sensors 406. The sensors 406 send a data signal 410to a control system 412.

The control system 412 may be part of a larger system, such as adistributed control system (DCS), a programmable logic controller (PLC),a direct digital controller (DDC), or any other appropriate controlsystem. Further, the control system 412 may automatically adjustparameters, or may provide information about the gas turbine 102 to anoperator who manually performs adjustments. The control system 412 isdiscussed further with respect to FIG. 14, below.

It will be understood that the gas turbine system 400 shown in FIG. 4,and similar gas turbine systems depicted in other figures, have beensimplified to assist in explaining various embodiments of the presenttechniques. Accordingly, in embodiments of the present techniques, boththe oxidant system 116 and the fuel system 114, as well as the gasturbine systems themselves, can include numerous devices not shown. Suchdevices can include flow meters, such as orifice flow meters, mass flowmeters, ultrasonic flow meters, venturi flow meters, and the like. Otherdevices can include valves, such as piston motor valves (PMVs) to openand close lines, and motor valves, such as diaphragm motor valves(DMVs), globe valves, and the like, to regulate flow rates. Further,compressors, tanks, heat exchangers, and sensors may be utilized inembodiments in addition to the units shown.

In the embodiment shown in FIG. 4, the compressor 104 may be used tocompress a stream 414, such as a recycled exhaust stream. Aftercompression, the stream 414 may be injected from a line 416 into themixing section of the combustor 110. The stream 414 is not limited to apure recycle stream, as the injected stream 416 may provide the oxidantto the combustor 110. The exhaust stream 418 from the expander exhaustsection 408 may be used to provide the recycle stream, as discussedfurther with respect to FIG. 12, below. The sensors 406 are not limitedto the expander exhaust section 408, but may be in any number of otherlocations. For example, the sensors 406 may be disposed in multiplerings around the expander exhaust section 408. Further, the sensors 406may be separated into multiple rings by the type of sensor 406, forexample, with oxygen analyzers in one ring and temperature sensors inanother ring. It will be apparent to one of skill in the art that anynumber of appropriate arrangements may be used. In addition to, or inplace of, sensors 406 in the exhaust expander, sensors may also bedisposed in other parts of the gas turbine 102, as discussed withrespect to FIGS. 5 and 6.

FIG. 5 is a schematic of a gas turbine system 500 that includes sensors502 on the turbine expander 106. The referenced units are as describedabove with respect to FIGS. 1 and 4. The sensors 502 on the turbineexpander 106 send a signal 504 back to the control system 412, which maybe used to make adjustment decisions for each, or all, of the combustors110. Any number of physical measurements could be performed on theexpander 106, for example, the sensors 106 could be used to measuretemperature, pressure, CO concentration, O₂ concentration, vibration,and the like. Further, multiple sensors 502 could be used to measurecombinations of these parameters. Placing sensors 502 on the turbineexpander 106 may increase the dependency of each of the sensors 502 onconditions in individual combustors 106, improving the efficiency ofcontrol algorithms. This may be further enhanced, as discussed withrespect to FIG. 6.

FIG. 6 is a schematic of a gas turbine system 600 that includes sensors602 on the exhaust line 604 out of each combustor 110. The referencedunits are as described above with respect to FIGS. 1 and 4. In thisembodiment, a signal 606 returned to the control system 412 from thesensor 602 that is specific to the individual combustor 110, enablingspecific control algorithms to be implements in the control system 412for each of the combustors 110. As discussed previously, the sensor 602may measure temperature, pressure, CO concentration, O₂ concentration,or any combinations thereof. This arrangement of sensors 602 may becombined with sensors 406 placed in the expander exhaust section 408, orin other locations, to provide data for both specific control of each ofthe combustors 110 and overall control data for the gas turbine 102.Other techniques may also be used in embodiments to gain further controlover the combustion process in each of the combustors 110, as discussedwith respect to FIG. 7.

FIG. 7 is a schematic of a gas turbine system 700 that includes aseparate oxidant flow adjusting valve 702 on the oxidant supply line 704for each combustor 110. As used herein, the oxidant flow adjusting valve702 can be any variable geometry system designed to control the flow ofa gas through a line. The referenced units are as described above withrespect to FIGS. 1, 4, and 6. An actuator 706 can be used by the controlsystem 412 to adjust the flow rate of oxidant through the oxidant flowadjusting valve 702. The oxidant flow adjusting valve 702 may operatetogether with the oxidant flow adjusting device 402 to regulate oxidantflow, providing a closer control of the combustion process in thecombustor 110. Further, in embodiments, an oxidant flow adjusting valve702 may be combined with a sensor 602 (FIG. 6) on the exhaust line 604from the combustor 110 to provide further control.

In embodiments the gas turbines 102 may be used to provide power, CO₂,heat energy, or any combinations thereof for numerous applications. Forexample, the heat from the exhaust may be recovered as discussed withrespect to FIG. 8.

Energy Recovery and Recycle of Exhaust

FIG. 8 is a schematic of a gas turbine system 800 that includes a heatrecovery steam generator (HRSG) 802 on the exhaust stream 418 from theexpander exhaust section 408. The referenced units are as describedabove with respect to FIGS. 1 and 4. The exhaust gas in the exhauststream 418 can include, but is not limited to, fuel, oxygen, carbonmonoxide, carbon dioxide, hydrogen, nitrogen, nitrogen oxides, argon,water, steam, or any combination thereof. The exhaust stream 418 canhave a temperature ranging from about 430° C. to about 725° C. and apressure of about 101 kPa to about 110 kPa.

In the embodiment shown in the schematic 800, the heat generated by thecombustion can be used to boil an inlet water stream 804 to generate asteam stream 806 that may also be superheated. The steam stream 806 maybe used, for example in a Rankine cycle to generate mechanical powerfrom a steam turbine, or to provide steam for utilities, or both. Themechanical power from the steam turbine may be used to generateelectricity, operate compressors, and the like. The system 800 is notlimited to a HRSG 802, as any type of heat recovery unit (HRU) may beused. For example, the heat may be recovered in a heat exchanger toprovide hot water or other heated fluids. Further, a Rankine cycle basedon an organic working fluid (ORC) may be used to recover heat energy byconverting it to mechanical energy.

The cooled exhaust stream 808 may then be used for other purposes, suchas to provide recycled exhaust for stream 414, as discussed below.Various sensors may be added to the system to monitor and control thesteam generation process, as discussed with respect to FIGS. 9 and 10.

FIG. 9 is a schematic of a gas turbine system 900 that includes a sensor902 on the exhaust stream 418 from the expander exhaust section 408 to aheat recovery steam generator (HRSG) 802. The referenced units are asdescribed above with respect to FIGS. 1, 4, and 8. A signal 904 isprovided from the sensor 902 to the control system 412. The sensor 902may be a temperature sensor, a pressure sensor, or any of the sensorsdiscussed previously. Further, the sensor 902 may be a single sensor ora group of sensors, and may be configured to provide information forcontrolling all of the combustors 110 to adjust the temperature of theexhaust stream 418 from the gas turbine 102 for controlling the HRSG802. In embodiments, the sensor 902 may be combined with any of thepreviously discussed sensor arrangements, for example, as shown withrespect to FIGS. 4, 5, and 6. The control of the HRSG 802 and gasturbine 102 may be further enhanced by sensors in other locations, asdiscussed with respect to FIG. 10.

FIG. 10 is a schematic of a gas turbine system 1000 that includes asensor 902 on the cooled exhaust stream 808 from the HRSG 802. Thereferenced units are as described above with respect to FIGS. 1, 4, and8. A signal 1004 is provided from the sensor 1002 to the control system412. The sensor 1002 may be a temperature sensor, a pressure sensor, orany of the sensors discussed previously. Further, the sensor 1002 may bea single sensor or a group of sensors, and may be configured to provideinformation for controlling all of the combustors 110 to adjust thetemperature of the exhaust stream 418 from the gas turbine 102. Thesignal 1004 may be used by the control system 412 to determine theamount of heat harvested by the HRSG 802 versus the amount of heatwasted in the cooled exhaust stream 808. In embodiments, the sensor 1002may be combined with any or all of the previously discussed sensorarrangements, for example, as shown with respect to FIGS. 4, 5, 6, and8. The heat in the cooled exhaust stream 808 from the HRSG 802 may betoo high for use in downstream units. Therefore a cooler may be used toremove excess heat, as discussed with respect to FIG. 11.

FIG. 11 is a schematic of a gas turbine system 1100 that includes acooler 1102 on the cooled exhaust stream 808 from the HRSG 802. Thereferenced units are as described above with respect to FIGS. 1, 4, 8,and 10. The cooler 1102 may be a non-contact heat exchanger, or anynumber of other types. For example, in an embodiment, the cooler 1102may be a counter-current direct contact heat exchanger, in which a waterstream 1104 is introduced at the top of a vessel, while the cooledexhaust stream 808 is introduced at the bottom of the vessel. As thewater contacts the hot exhaust, it cools the stream by both evaporationand heat exchange. A heated water stream 1106 is removed from the bottomof the vessel, and may be cooled before being recycled as the waterstream 1104. The outlet exhaust stream 1108 is both cooled and saturatedwith water vapor, and may be used as a recycle stream, for example tostream 414, as discussed with respect to FIG. 12.

FIG. 12 is a schematic of a gas turbine system 1200 that combinesfeatures from a number of the systems discussed above. The referencedunits are as described above with respect to FIGS. 1, 4, 8, and 11. Inthis embodiment, the saturated exhaust gas 1202 from the cooler 1102 maybe recycled to the inlet of the compressor 104. After compression, thesaturated exhaust gas 1202 may be fed to the combustor 110 as stream 416to assist with cooling the combustor 110. A portion of stream 416 may bediverted as an extracted side stream 1204 to a processing system forother use. The processing system may purify the CO₂ in the side stream1204, such as by conversion or removal of any CO and O₂, for injectioninto a hydrocarbon reservoir to enhance oil recovery. Other uses for thediverted gas may include carbon sequestration. In this application, theside stream 1204 may be directly injected into a underground formationfor disposal.

Individual Control of Equivalence Ratio to Combustors

The gas turbine systems discussed above may be used to control thecombustion process in each of the combustors 110 individually and as agroup. As previously mentioned, one goal of the control may be tobalance the equivalence ratio of the fuel and oxygen. This may beperformed to minimize unburned or partially burned hydrocarbon,represented by the CO concentration in an exhaust stream and to minimizeunconsumed oxygen in the exhaust stream. The equivalence ratio isdiscussed further with respect to FIG. 13.

FIGS. 13A and 13B are graphical depictions of a simulation showing therelationship between the concentration of oxygen and carbon monoxide asthe equivalence ratio (ϕ) changes from 0.75 to 1.25 and from 0.999 to1.001, respectively. The highest efficiency may be achieved when theequivalence ratio is about 1.0. The oxygen concentration as a functionof the equivalence ratio is shown as line 1310 and the carbon monoxideconcentration as a function of the equivalence ration is shown as line1320. The equivalence ratio (ϕ) is equal to (mol % fuel/mol %oxygen)_(actual)/(mol % fuel/mol % oxygen)_(stoichiometric). The mol %fuel is equal to F_(fuel)/(F_(oxygen)+F_(fuel)), where F_(fuel) is equalto the molar flow rate of fuel and F_(oxygen) is equal to the molar flowrate of oxygen.

The mol % oxygen is equal to F_(oxygen)/(F_(oxygen)+F_(fuel)), whereF_(oxygen) is equal to the molar flow rate of oxygen and F_(fuel) isequal to the molar flow rate of fuel. The molar flow rate of the oxygendepends on the proportion of oxygen to diluent in the oxidant mixture,and may be calculated as F_(oxygen)/(F_(oxygen)+F_(diluent)). As usedherein, the flow rate of the oxidant may be calculated asF_(oxidant)−(F_(oxygen)+F_(diluent)).

As the equivalence ratio (ϕ) goes below 1 or above 1 the mole fractionor concentration of oxygen and carbon dioxide in the exhaust gaschanges. For example, as the equivalence ratio (ϕ) goes below 1 the molefraction of oxygen rapidly increases from about 1 ppm (i.e., an oxygenmole fraction of about 1.0×10⁻⁶) at an equivalence ratio (ϕ) of about 1to about 100 ppm (i.e., an oxygen mole fraction of about 1×10⁻⁴) at anequivalence ratio of about 0.999. Similarly, as the equivalence ratio(ϕ) goes above 1 the concentration of carbon monoxide rapidly increasefrom about 1 ppm (i.e., carbon monoxide mole fraction of about 1×10⁻⁶)at an equivalence ratio (ϕ) of about 0.9995 to greater than about 100ppm (i.e., a carbon monoxide mole fraction of about 1×10⁻⁴) at anequivalence ratio (ϕ) of about 1.001.

Based, at least in part, on the data obtained from the sensors, such assensors 406 (FIG. 4), 502 (FIG. 5), or 602 (FIG. 6), the amount ofoxidant 116 and/or the amount of fuel 114 to each of the combustors 110can be adjusted to produce an exhaust stream 418 having a desiredcomposition. For example, monitoring the oxygen and/or carbon monoxideconcentration in the exhaust gas in the expander exhaust section 408,the turbine expander 106, or the exhaust line 604 allows the individualadjustment of the amount of oxidant 116 and fuel 114 introduced to eachcombustor 110 to be controlled such that combustion of the fuel iscarried out within a predetermined range of equivalence ratios (ϕ) inthat combustor 110. This can be used to produce an exhaust stream 418having a combined concentration of oxygen and carbon monoxide of lessthan about 3 mol %, less than about 2.5 mol %, less than about 2 mol %,less than about 1.5 mol %, less than about 1 mol %, or less than about0.5 mol %. Furthermore, the exhaust stream 418 may have less than about4,000 ppm, less than about 2,000 ppm, less than about 1,000 ppm, lessthan about 500 ppm, less than about 250 ppm, or less than about 100 ppmcombined oxygen and carbon monoxide.

A desired or predetermined range for the equivalence ratio (ϕ) in eachcombustor 110 can be calculated or entered to carry out the combustionof the fuel 114 to produce an mixed exhaust stream 418 containing adesired amount of oxygen and/or carbon monoxide. For example, theequivalence ratio (ϕ) in each combustor 110 can be maintained within apredetermined range of from about 0.85 to about 1.15 to produce anexhaust stream 418 having a combined oxygen and carbon monoxideconcentration ranging from a low of about 0.5 mol %, about 0.8 mol %, orabout 1 mol %, to a high of about 1.5 mol %, about 1.8 mol %, about 2mol %, or about 2.2 mol %. In another example, the equivalence ratio (ϕ)in each combustors 110 can be maintained within a range of about 0.85 toabout 1.15 to produce an exhaust stream 418 having a combined oxygen andcarbon monoxide concentration of less than 2 mol %, less than about 1.9mol %, less than about 1.7 mol %, less than about 1.4 mol %, less thanabout 1.2 mol %, or less than about 1 mol %. In still another example,the equivalence ratio (ϕ) in each of the combustors 110 can bemaintained within a range of from about 0.96 to about 1.04 to produce anexhaust stream 418 having a combined oxygen and carbon monoxideconcentration of less than about 4,000 ppm, less than about 3,000 ppm,less than about 2,000 ppm, less than about 1,000 ppm, less than about500 ppm, less than about 250 ppm, or less than about 100 ppm.

It will be noted that the combustors 110 do not have to be at the sameset-point, or even within the same range. In embodiments of the presenttechniques, different or biased set-points may be used for each of thecombustors 110 to account for differences in construction, performance,or operation. This may avoid a situation in which different operationalcharacteristics of different combustors 110 cause the exhaust stream 418to be contaminated with unacceptable levels of oxygen or carbonmonoxide.

Accordingly, in embodiments of the present techniques, two methods foroperating the gas turbine 102 are used. In a first method, the entireset of combustors 110 is operated as a single entity, for example,during startup and in response to global set-point adjustments, such asspeed or power changes. In a second method, the individual combustors110 may be separately biased, for example, to compensate for differencesin wear, manufacturing, and the like.

One method for operating the entire set of combustors 110 can includeinitially, i.e., on start-up, introducing the fuel 114 and oxygen in theoxidant 116 at an equivalence ratio greater than 1. For example, theequivalence ratio (ϕ) at startup may range from a low of about 1.0001,about 1.0005, about 1.001, about 1.05, or about 1.1, to a high of about1.1, about 1.2, about 1.3, about 1.4, or about 1.5. In another example,the equivalence ratio (ϕ) can range from about 1.0001 to about 1.1, fromabout 1.0005 to about 1.01, from about 1.0007 to about 1.005, or fromabout 1.01 to about 1.1. For global adjustments, the concentration ofoxygen and/or carbon monoxide in the exhaust stream 418 can bedetermined or estimated via the sensors 406, 502, or 902. The expandedexhaust gas in the exhaust stream 418 may initially have a highconcentration of carbon monoxide (e.g., greater than about 1,000 ppm orgreater than about 10,000 ppm) and a low concentration of oxygen (e.g.,less than about 10 ppm or less than about 1 ppm).

Another method for operating the entire set of combustors 110 caninclude initially, i.e., on start-up, introducing the fuel 114 andoxygen in the oxidant 116 at an equivalence ratio of less than 1. Forexample, the equivalence ratio (ϕ) at startup may range from a low ofabout 0.5, about 0.6, about 0.7, about 0.8, or about 0.9 to a high ofabout 0.95, about 0.98, about 0.99, about 0.999. In another example, theequivalence ratio (ϕ) can range from about 0.9 to about 0.999 from about0.95 to about 0.99, from about 0.96 to about 0.99, or from about 0.97 toabout 0.99. The expanded exhaust gas in the exhaust stream 418 shouldinitially have a high concentration of oxygen (e.g., greater than about1,000 ppm or greater than about 10,000 ppm) and a low concentration ofcarbon monoxide (e.g., less than about 10 ppm or even less than about 1ppm).

For example, when the concentration of oxygen in the exhaust gasincreases from less than about 1 ppm to greater than about 100 ppm,about 1,000 ppm, about 1 mol %, about 2 mol %, about 3 mol %, or about 4mol %, an operator, the control system 412, or both can be alerted thatan equivalence ratio (ϕ) of less than 1 has been reached. In one or moreembodiments, the amount of oxygen via oxidant 116 and fuel 114 can bemaintained constant or substantially constant to provide a combustionprocess having an equivalence ratio (ϕ) of slightly less than 1, e.g.,about 0.99. The amount of oxygen via oxidant 116 can be decreased and/orthe amount of fuel 114 can be increased and then maintained at aconstant or substantially constant amount to provide a combustionprocess having an equivalence ratio (ϕ) falling within a predeterminedrange. For example, when the concentration of oxygen in the exhauststream 418 increases from less than about 1 ppm to about 1,000 ppm,about 0.5 mol %, about 2 mol %, or about 4 mol %, the amount of oxygenintroduced via the oxidant 116 can be reduced by an amount ranging froma low of about 0.01%, about 0.02%, about 0.03%, or about 0.04 to a highof about 1%, about 2%, about 3%, or about 5% relative to the amount ofoxygen introduced via the oxidant 116 at the time the increase in oxygenin the exhaust gas is initially detected. In another example, when theconcentration of oxygen in the exhaust stream 418 increases from lessthan about 1 ppm to about 1,000 ppm or more the amount of oxygenintroduced via the oxidant 116 can be reduced by about 0.01% to about2%, about 0.03% to about 1%, or about 0.05% to about 0.5% relative tothe amount of oxygen introduced via the oxidant 116 at the time theincrease in oxygen in the exhaust gas is detected. In still anotherexample, when the concentration of oxygen increases from less than about1 ppm to about 1,000 ppm or more the amount of fuel 114 can be increasedby an amount ranging from a low of about 0.01%, about 0.02%, about0.03%, or about 0.04 to a high of about 1%, about 2%, about 3%, or about5% relative to the amount of fuel 114 introduced at the time theincrease in oxygen in the exhaust gas is initially detected.

During operation of the gas turbine system 102, the equivalence ratio(ϕ) can be monitored via the sensors 406, 502, or 602 on a continuousbasis, at periodic time intervals, at random or non-periodic timeintervals, when one or more changes to the gas turbine system 102 occurthat could alter or change the equivalence ratio (ϕ) of the exhauststream 418, or any combination thereof. For example, changes that couldoccur to the gas turbine system 102 that could alter or change theequivalence ratio (ϕ) can include a change in the composition of thefuel, a change in the composition of the oxidant, or a combinationthereof. As such, the concentration of oxygen and/or carbon monoxide,for example, can be monitored, and adjustments can be made to the amountof oxidant 116 and/or fuel 114 to control the amounts of oxygen and/orcarbon monoxide in the exhaust stream 418.

In at least one embodiment, reducing the equivalence ratio (ϕ) can becarried out in incremental steps, non-incremental steps, a continuousmanner, or any combination thereof. For example, the amount of oxidant116 and/or the fuel 114 can be adjusted such that the equivalence ratio(ϕ) changes by a fixed or substantially fixed amount per adjustment tothe oxidant 116 and/or fuel 114, e.g., by about 0.001, by about 0.01, orby about 0.05. In another example, the amount of oxidant 116 and/or fuel114 can be continuously altered such that the equivalence ratiocontinuously changes. Preferably the amount of oxidant 116 and/or fuel114 is altered and combustion is carried out for a period of timesufficient to produce an exhaust gas of substantially consistentcomposition, at which time the amount of oxidant 116 and/or fuel 114 canbe adjusted to change the equivalence ratio (ϕ) in an amount rangingfrom a low of about 0.00001, about 0.0001, or about 0.0005 to a high ofabout 0.001, about 0.01, or about 0.05. After the exhaust stream 418achieves a substantially consistent concentration of oxygen the oxidant116 and/or fuel 114 can again be adjusted such that the equivalenceratio (ϕ) changes. The amount of oxygen and/or carbon monoxide in theexhaust stream 418 can be monitored and the amount of oxidant 116 and/orfuel 114 can be repeatedly adjusted until the exhaust stream 418 has acombined concentration of oxygen and carbon monoxide, for example, ofless than about 2 mol % or less than about 1.5 mol %, or less than about1 mol %.

The combustors 110 can be operated on a continuous basis such that theexhaust stream 418 has a combined oxygen and carbon monoxideconcentration of less than 2 mol %, less than 1 mol %, less than 0.5 mol%, or less than about 0.1 mol %. In another example, the time duringwhich combustion is carried out within the combustors 110, the exhauststream 418 can have a combined oxygen and carbon monoxide concentrationof less than 2 mol % or less than about 1 mol % for about 50%, 55%, 60%,65%, 70%, 75%, 80%, 85%, 90%, or about 95% of the time during which thegas turbine 102 is operated. In other words, for a majority of the timethat combustion is carried out within the combustors 110, the exhauststream 418 can have a combined oxygen and carbon monoxide concentrationof less than about 2 mol %, less than about 1 mol %, less than about 0.5mol %, or less than about 0.1 mol %.

Once the overall control of the gas turbine 102 is set, the biasingneeded for individual combustors 110 may be determined in the secondmethod. For example, referring to FIG. 4, based on data signals 410 fromthe sensors 406 in the expander exhaust section 408, the oxidant flowadjusting device 402 for each individual combustor 110 can be adjustedby the control system 412 to maintain the measured value of the sensors406 at or near to a desired set-point. Several calculated values may bedetermined from the measured values of each sensor 406. These mayinclude, for example, an average value that can be used to make similaradjustments to all of the oxidant flow adjusting devices 402 in theindividual combustors 110, as discussed with respect to the firstmethod.

In addition, various difference values, for example, calculated based ondifferences of the measured values of two or more sensors 406, may beused to make biasing adjustments to the oxidant flow adjusting devices402 on one or more of the combustors 110 to minimize differences betweenthe measured values of the sensors 406. The control system 412 may alsoadjust the oxidant system 116 directly, such by adjusting compressorinlet guide vanes (IGV) or a speed control to change the oxidant flowrates, for example, to all of the combustors 110 at once. Further, thecontrol system 412 can make similar adjustments to the fuel 114 to allcombustors 110, depending, for example, on the speed selected for thegas turbine 102. As for the oxidant, the fuel supply to each of thecombustors 110 may be individually biased to control the equivalenceratio of the burn. This is discussed further with respect to FIG. 15.

FIG. 14 is a block diagram of a method 1400 for biasing individualcombustors 110 based on readings from an array of sensors 406. It can beassumed that the gas turbine 102 has been started before this method1400 begins, and that all of the combustors 110 are using essentiallythe same mixture or a previous operation point. The method 1400 beginsat block 1402 at which readings are obtained from the sensors 406 or502. At block 1404, sums and differences are determined between themeasurements obtained from the individual sensors 406 or 502. At block1406, the sums and differences may be combined to assist in identifyingthe combustors 110 that are contributing to a high oxygen or high carbonmonoxide condition in the exhaust. This may also be performed by a swirlchart, as described above. Adjustments to the fuel 114 and oxidant 116for those combustors 110 are calculated at block 1408, for example,using the same considerations for the particular combustors 110 involvedas used for adjusting all of the combustors 110 in the first method. Atblock 1410, the new set-point for the oxidant 116 is entered and oxidantis provided to the combustors 110. In a substantially simultaneousmanner, at block 1412, a new set-point is entered for the fuel 114, andfuel 114 is provided to the combustors 110. At block 1414, thecombustion process consumed the fuel 114 and oxidant 116 provided.Process flow then returns to block 1402, wherein the method repeats.

More precise measurements may be used to provide finer control over thecombustion process. For example, in the sensor arrangement shown in FIG.6, each combustor 110 has a separate sensor 602 located on an exhaustline 604 from the combustor 110. In this embodiments, the effects ofchanges to individual combustors 110 may be made, and a preciseadjustment to the oxidant 116 and fuel 114 may be made for any combustor110 providing too high of an oxygen or carbon monoxide exhaust, forexample, using the techniques discussed with respect to the firstmethod. These adjustments may be made in addition to any uniformadjustments made in the entire set of combustors 110, for example, inresponse to a set-point change in the operating speed of the gas turbine102.

Control System

FIG. 15 is a block diagram of a plant control system 1500 that may beused to individually control the oxidant 116 and fuel 114 to a number ofcombustors 110 in a gas turbine 102. As previously mentioned, thecontrol system 1600 may be a DCS, a PLC, a DDC, or any other appropriatecontrol device. Further, any controllers, controlled devices, ormonitored systems, including sensors, valves, actuators, and othercontrols, may be part of a real-time distributed control network, suchas a FIELDBUS system, in accordance with IEC 61158. The plant controlsystem 1500 may host the control system 412 used for each of theindividual combustors 110 on gas turbines 102 in a plant or facility.

The control system 1500 may have a processor 1502, which may be a singlecore processor, a multiple core processor, or a series of individualprocessors located in systems through the plant control system 1500. Theprocessor 1502 can communicate with other systems, including distributedprocessors, in the plant control system 1500 over a bus 1504. The bus1504 may be an Ethernet bus, a FIELDBUS, or any number of other buses,including a proprietary bus from a control system vendor. A storagesystem 1506 may be coupled to the bus 1504, and may include anycombination of non-transitory computer readable media, such as harddrives, optical drives, random access memory (RAM) drives, and memory,including RAM and read only memory (ROM). The storage system 1506 maystore code used to provide operating systems 1508 for the plant, as wellas code to implement turbine control systems 1510, for example, bases onthe first or second methods discussed above.

A human-machine interface 1512 may provide operator access to the plantcontrol system 1500, for example, through displays 1514, keyboards 1516,and pointing devices 1518 located at one or more control stations. Anetwork interface 1520 may provide access to a network 1522, such as alocal area network or wide area network for a corporation.

A plant interface 1524 may provide measurement and control systems for afirst gas turbine system. For example, the plant interface 1524 may reada number of sensors 1526, such as the sensors 406, 502, 602, 902, and1002 described with respect to FIGS. 4, 5, 6, 9, and 10. The plantinterface 1524 may also make adjustments to a number of controls,including, for example, fuel flow controls 1528 used adjust the fuel 114to the combustors 110 on the gas turbine 102. Other controls include theoxidant flow controls 1530, used, for example, to adjust the actuator404 on an oxidant flow adjusting device 402, the actuator 706 on aoxidant flow adjusting valve 702, or both, for each of the combustors110 on the gas turbine 102. The plant interface 1524 may also controlother plant systems 1532, such as generators used to produce power fromthe mechanical energy provided by the gas turbine 102. The additionalplant systems 1532 may also include the compressor systems used toprovide oxidant 116 to the gas turbine 102.

The plant control system 1500 is not limited to a single plant interface1524. If more turbines are added, additional plant interfaces 1534 maybe added to control those turbines. Further, the distribution offunctionality is not limited to that shown in FIG. 15. Differentarrangements could be used, for example, one plant interface systemcould operate several turbines, while another plant interface systemcould operate compressor systems, and yet another plant interface couldoperate generation systems.

While the present techniques may be susceptible to various modificationsand alternative forms, the exemplary embodiments discussed above havebeen shown only by way of example. However, it should again beunderstood that the techniques is not intended to be limited to theparticular embodiments disclosed herein. Indeed, the present techniquesinclude all alternatives, modifications, and equivalents falling withinthe true spirit and scope of the appended claims.

What is claimed is:
 1. A gas turbine system, comprising: an oxidantsystem; a fuel system; a control system; a plurality of combustorsadapted to receive and combust an oxidant from the oxidant system and afuel from the fuel system to produce a plurality of exhaust gases; aplurality of fuel-flow adjustment devices, wherein each of the pluralityof fuel-flow adjustment devices is operatively associated with one ofthe plurality of combustors, wherein at least one of the fuel-flowadjustment devices is configured to independently regulate a fuel flowrate into an associated combustor to achieve substantiallystoichiometric combustion; and a plurality of exhaust sensors incommunication with the control system, wherein the exhaust sensors areadapted to measure an oxygen concentration and a carbon monoxideconcentration in each of the plurality of exhaust gases, and wherein thecontrol system is configured to independently adjust at least one of theplurality of fuel-flow adjustment devices based, at least in part, onthe oxygen concentrations and carbon monoxide concentrations measured bythe plurality of exhaust sensors to maintain a combined oxygen andcarbon monoxide concentration of the plurality of exhaust gases within apredetermined range.
 2. The system of claim 1, wherein the oxidantcomprises oxygen and a diluent.
 3. The system of claim 1, furthercomprising a diluent supply provided to each of the plurality ofcombustors.
 4. The system of claim 1, further comprising an oxidantcompressor adapted to provide compressed oxidant to each of theplurality of combustors.
 5. The system of claim 1, wherein the controlsystem is adapted to regulate fuel flow rates into the plurality ofcombustors using the plurality of fuel-flow adjustment devices so as tominimize differences between measured parameters at different exhaustsensors.
 6. The system of claim 1, further comprising a turbine expanderadapted to receive the exhaust gas and to generate power.
 7. The systemof claim 6, further comprising a heat recovery steam generator adaptedto receive the exhaust gas from the turbine expander and to generatepower.
 8. The system of claim 6, further comprising a diluent compressorand an exhaust gas recirculation loop adapted to receive the exhaust gasfrom the expander, wherein the exhaust gas recirculation loop comprisesa heat recovery steam generator adapted to generate power, and a cooledexhaust line adapted to provide cooled exhaust gas to the diluentcompressor, and wherein the diluent compressor is adapted to providecompressed diluent to the combustor.
 9. The system of claim 8, furthercomprising an exhaust gas extraction system disposed between the diluentcompressor and the combustor, wherein the exhaust gas extraction systemis adapted to extract diluent at elevated pressures.
 10. The gas turbinesystem of claim 1, wherein the predetermined range is between 0.01 mol %and about 3 mol % combined oxygen and carbon monoxide concentration. 11.The system of claim 1, wherein the plurality of exhaust sensors arefurther adapted to measure a temperature of the exhaust gas.
 12. Amethod of controlling a gas turbine, the method comprising: providing anoxidant to a plurality of combustors on a gas turbine; providing a fuelto the plurality of combustors, wherein a fuel flow rate isindependently adjusted for each of the plurality of combustors;substantially stoichiometrically combusting the fuel and the oxidant ineach of the plurality of combustors to produce a plurality of exhaustgases; measuring an oxygen concentration and a carbon monoxideconcentration in each of the plurality of exhaust gases; and adjustingthe fuel flow rate into each of the plurality of combustors based on themeasured oxygen concentrations and carbon monoxide concentrations tomaintain a combined oxygen and carbon monoxide concentration of theplurality of exhaust gases within a predetermined range.
 13. The methodof claim 12, further comprising compressing the oxidant before theoxidant is provided to each of the plurality of combustors.
 14. Themethod of claim 12, further comprising returning a portion of theexhaust gas to the plurality of combustors as a diluent.
 15. The methodof claim 14, further comprising compressing the diluent with acompressor before the diluent enters the combustor.
 16. The method ofclaim 15, further comprising extracting at least a portion of theexhaust gas from a coupling disposed between the compressor and each ofthe plurality of combustors, wherein the amount of exhaust gas extractedis based, at least in part, on the measured oxygen and carbon monoxideconcentrations.
 17. The method of claim 12, wherein the predeterminedrange is between 0.01 mol % and about 3 mol % combined oxygen and carbonmonoxide concentration.
 18. A non-transitory computer readable mediumcomprising code configured to direct a processor to: provide an oxidantto a plurality of combustors on a gas turbine; provide a fuel to theplurality of combustors, wherein a fuel flow rate is independentlyadjusted for each of the plurality of combustors; monitor an oxygenconcentration and a carbon monoxide concentration in each of a pluralityof exhaust gases produced in a flame in each of the plurality ofcombustors; and adjust the fuel flow rate into each of the plurality ofcombustors based on the measured oxygen concentrations and carbonmonoxide concentrations to maintain a combined oxygen and carbonmonoxide concentration of the plurality of exhaust gases within apredetermined range to achieve substantially stoichiometric combustion.19. The non-transitory computer readable medium of claim 18, comprisingcode configured to direct the processor to compare measurementsassociated with a plurality of sensors to the data structure todetermine which of the plurality of combustors to adjust.
 20. Thenon-transitory computer readable medium of claim 18, comprising codeconfigured to direct the processor to regulate fuel flow rates to eachof the plurality of combustors so as to minimize differences betweenmeasured oxygen concentrations and carbon monoxide concentrations atdifferent exhaust sensors.